Drilling a modern oil well involves the use of expensive and sophisticated heavy equipment that is complicated in its set-up and operation. As such, drilling an oil well also requires the skilled involvement of experienced and well trained operators to ensure that all aspects of the drilling process are executed efficiently and safely. Proper procedures at all steps of the process must be followed to prevent accidents, minimize the risk of damage to the equipment and also ensure that the actual drilling process is successful.
With regards to the drilling process itself, skilled operators manage the operation of the drilling equipment using established procedures and protocols to initiate the drilling process, monitor the drilling as it progresses and react to situations as they may occur. Due to the harshness of the environment and the complexities and variables ever present in drilling an oil well, it is well known that it is often difficult for the human operator to optimize the dynamic process as drilling continues. That is, the operator must generally balance a number of parameters in order to maintain effective and/or efficient drilling rates through particular formation rock while also operating within the performance specifications for the equipment involved. For example, the operator must monitor and control various parameters such as rate of penetration (ROP), weight on bit (WOB), drilling fluid flow rates, differential pressure (DP), motor speeds as well as other parameters during the drilling process.
As is known, adjusting the rate of release of the drillstring is one way in which the drilling process can be controlled. In controlling the rate of the release of the drillstring, the operator will be looking to control the amount of force that is being applied by the drillbit against the formation rock. That is, depending on the relative hardness of the rock the operator will look to optimize the drilling through that particular rock wherein the force being applied to the rock face is generally less than the total weight of the drillstring. Thus, the rate at which the drillstring is being lowered into the well bore must be controlled in order that the total force of the drill bit against the rock at the bottom of the well is maintained within desired ranges.
However, in many circumstances there is no quantitative measurement of downhole conditions. As such, the operator often conducts drilling operations based on “feel” that they may have developed over time from their experience in the field. However, while operator “feel” can be effective, it is only a qualitative determination of drilling performance and, as a result, presents significant risks to the operators in terms of operational efficiency of drilling as well as potentially increasing the risk of damaging drilling equipment.
Moreover, the situation becomes more complicated when drilling off-vertical or horizontal wells. In these types of wells, as the drillstring deviates from the vertical, the drillstring becomes at least partially supported by the formation. As such, the measured weight of the drillstring becomes difficult to measure at surface simply based on the hook load. As a result, in this type of well the WOB often cannot be accurately determined simply by measuring weight at surface. Moreover, as the driller may be required to apply a substantial downhole force on the drillstring simply to overcome the friction of the drillstring lying against the formation, the actual force being applied at the bit face may be substantially less than measured forces at surface. In other words, the measured value of downhole force as determined at the surface does not reflect the actual value of force that may exist at the drillbit.
As such, differential pressure (DP), measured as the difference in drilling fluid pressure between the motor and system pressure losses in a non-drilling state and the pressure with the bit against the formation, can be used as an effective parameter to determine the actual force being applied to the formation face by the drillbit. For example, a particular downhole motor may typically operate with a pressure of 1000 psi. The 1000 psi value may indicate that there is no force being applied on the drillbit at the formation face. In other words, a measured DP of 1000 psi simply indicates that the drillbit is spinning. However, as force is applied against the formation face, the required operating pressure to maintain optimum torque of the drillbit against the formation will increase as the resistance to drilling fluid flow increases due to the force of the drillbit against the formation face. Similarly, as drilling progresses and material is removed from the formation face, the force against the formation face will decrease which can be seen as a drop in pressure at surface. Thus, DP can be an effective parameter in determining how well drilling is progressing in some wells or at certain times of the drilling process.
In the past, in order to overcome these problems, autodrilling systems have been developed and utilized in order to at least partially automate the drilling process. In an automatic drilling process, drilling is controlled by equipment that typically obtains inputs from various sensors, feeds the input data to a controller that interprets the inputs and provides an output to drilling equipment.
Such systems, in various forms, have been applied to typical drilling equipment and specifically the hoist system of a drilling rig. The automatic control equipment is attached to the hoist system and its specific components such as a drawworks, drawworks brake and the cabling that controls the upward and downward motion of the drillstring. That is, in most rigs, the drawworks is activated to lift the drillstring and the drawworks brake is used to control lowering of the drillstring. Thus, in the traditional rig, no downward force above that of the weight of the drillstring can be applied to drillstring.
In other drilling systems no drawworks are used. In these systems, a hydraulic lifting system is utilized that allows both a lifting force and a downward force to be applied to the drillstring. Importantly, the downward force can be substantially higher than simply the weight of the drillstring as a downward hydraulic pressure can be applied to the drillstring. Such systems are effective in off-vertical wells.
In controlling the drilling process, the more parameters that can be effectively utilized within the drilling process, the more precisely the drilling process can be controlled with its attendant benefits on results but also decreased maintenance requirements if the equipment is being operated within preferred operational ranges.
A review of the prior art reveals that various automatic drilling systems have been developed in the past. For example, U.S. Pat. No. 7,713,442 teaches a system for drilling a borehole in which a first motor coupled to a drawworks is used to raise and lower a drill stem and a second motor rotates the drill stem. The system includes a control circuit that is coupled to the motors and sensors that obtain information including ROP, WOB, hook load and rotational speed. U.S. Pat. No. 5,474,142 describes an automatic drilling system that regulates drilling through a combination of drilling parameters on a drilling rig having a drawworks.
Accordingly, there continues to be a need for improved autodrilling systems and, in particular, for autodrilling systems that control a hydraulic hoist system on a rig with a broader range of potential control parameters.